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This is a copyrighted material and is being distributed to designated people only for the purposerevision to this document. It must not be copied or distributed without prior approval from AGA

Measurement of Gas by

Multipath Ultrasonic Meters

Transmission Measurement CommitteeReport No. 9

Copyright 1998 American Gas AssociationAll Rights Reserved

Operating SectionAmerican Gas Association

1515 Wilson BoulevardArlington, Virginia 22209

U.S.A.

Catalog No. XQ9801

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DISCLAIMERS AND COPYRIGHT

Nothing contained in any American Gas Association (A.G.A.) publication is to be construed as grantingany right, by implication or otherwise, for the manufacture, sale or use in connection with any method,apparatus or product covered by letters patent, nor as insuring anyone against liability for infringement

of letters patent.

This A.G.A. publication may be used by anyone desiring to do so. Efforts have been made to ensure the

accuracy and reliability of the data contained in this publication; however, A.G.A. makes norepresentation, warranty or guarantee in connection with A.G.A. publications and hereby expresslydisclaims any liability or responsibility for loss or damage resulting from their use; for any violation ofany federal, state or municipal regulation with which an A.G.A. publication may conflict; or for theinfringement of any patent from the use of any A.G.A. publication. Nothing contained in this reportshould be viewed as an endorsement by A.G.A. of any particular manufacturers products.

Copyright1998 American Gas Association, All Rights Reserved

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FOREWORD

This report is published as a recommended practice and is not issued as a standard. It has been written inthe form of a performance-based specification. Multipath ultrasonic meters should meet or exceed theaccuracy, functional and testing requirements specified in this report and users should follow the applicable

installation recommendations.

A.G.A. Engineering Technical Note M-96-2-3, Ultrasonic Flow Measurement for Natural Gas

Applications, is included in Appendix C, as a source of background information on ultrasonic gasmetering. Contents of this technical note were based on the information available when the note was writtenin March 1996. Therefore, in case of any conflict between the information in the main report and thetechnical note (Appendix C) the content in the main report prevails.

Research test results and flow-meter calibration data have indicated that multipath ultrasonic flow meterscan accurately measure gas flow rate when installed with upstream piping lengths sufficient to producefully developed turbulent flow-velocity profiles. Various combinations of upstream fittings, valves andlengths of straight pipe can produce profile disturbances at the meter inlet that may result in flow-ratemeasurement errors. The amount of meter error will depend on the magnitude of the inlet velocity profile

distortion produced by the upstream piping configuration and the meters ability to compensate for thisdistortion. Other effects that may also result in flow-rate measurement errors for a given installationinclude levels of pulsation, range of operating pressures and ambient temperature conditions.

A flow calibration of each meter may be necessary to meet the accuracy requirements specified in thisreport. Flow-calibration guidelines are provided for occasions when a flow calibration is requested by theuser to verify the meters accuracy or to apply a calibration factor to minimize the measurementuncertainty (see Appendix A).

Unlike most traditional gas meters, multipath ultrasonic meters inherently have an embeddedmicroprocessor system. Therefore, this report includes, by reference, a standardized set of internationaltesting specifications applicable to electronic gas meters. These tests, summarized in Appendix B, are usedto demonstrate the acceptable performance of the multipath ultrasonic meters electronic system design

under different influences and disturbances.

This report offers general criteria for the measurement of gas by multipath ultrasonic meters. It is thecumulative result of years of experience of many individuals and organizations acquainted with measuringgas flow rate. Changes to this report may become necessary from time to time. When any revisions aredeemed advisable, recommendations should be forwarded to: Operating Section, American GasAssociation, 1515 Wilson Boulevard, Arlington, VA 22209, U.S.A. A form is included for that purposeat the end of this report.

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ACKNOWLEDGMENTS

Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters, was developed by aTransmission Measurement Committee (TMC) task group

A.G.A.s Transmission Measurement Committee members represent a broad base of experience innatural gas measurement technologies. Through its committee structure, A.G.A. provides themechanism by which these committee members experiences and technical expertise are usedcollectively to prepare industry guidelines, recommendations and reports.

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TABLE OF CONTENTS

1 INTRODUCTION............................................................................................................1

1.1 Scope.....................................................................................................................................................................1

1.2 Principle of Measurement..................................................................................................................................1

2 TERMINOLOGY.............................................................................................................1

3 OPERATING CONDITIONS...........................................................................................2

3.1 Gas Quality..........................................................................................................................................................2

3.2 Pressures..............................................................................................................................................................2

3.3 Temperatures, Gas and Ambient......................................................................................................................2

3.4 Gas Flow Considerations....................................................................................................................................3

3.5 Upstream Piping and Flow Profiles .................................................................................................................3

3.6 Acoustic Noise......................................................................................................................................................3

4 METER REQUIREMENTS.............................................................................................5

4.1 Codes and Regulations.......................................................................................................................................5

4.2 Meter Body..........................................................................................................................................................54.2.1 Maximum Operating Pressure.......................................................................................................................5

4.2.2 Corrosion Resistance.....................................................................................................................................5

4.2.3 Meter Body Lengths and Bores.....................................................................................................................5

4.2.4 Ultrasonic Transducer Ports.........................................................................................................................6

4.2.5 Pressure Tap..................................................................................................................................................6

4.2.6 Miscellaneous................................................................................................................................................6

4.2.7 Meter Body Markings....................................................................................................................................6

4.3 Ultrasonic Transducers......................................................................................................................................7

4.3.1 Specifications.................................................................................................................................................7

4.3.2 Rate of Pressure Change................................................................................................................................7

4.3.3 Exchange.......................................................................................................................................................7

4.3.4 Transducer Tests............................................................................................................................................7

4.4 Electronics...........................................................................................................................................................8

4.4.1 General Requirements...................................................................................................................................8

4.4.2 Output Signal Specifications.........................................................................................................................8

4.4.3 Electrical Safety Design Requirements.........................................................................................................8

4.4.4 Component Replacement...............................................................................................................................9

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4.5 Computer Programs...........................................................................................................................................9

4.5.1 Firmware........................................................................................................................................................9

4.5.2 Configuration and Maintenance Software....................................................................................................9

4.5.3 Inspection and Auditing Functions.............................................................................................................10

4.5.4 Alarms.........................................................................................................................................................10

4.5.5 Diagnostic Measurements...........................................................................................................................10

4.5.6 Engineering Units........................................................................................................................................11

4.6 Documentation...................................................................................................................................................11

4.6.1 After Receipt of Order.................................................................................................................................12

4.6.2 Before Shipment..........................................................................................................................................12

5 PERFORMANCE REQUIREMENTS............................................................................12

5.1 Definitions..........................................................................................................................................................13

5.2 General...............................................................................................................................................................15

5.2.1 Large Meter Accuracy................................................................................................................................15

5.2.2 Small Meter Accuracy................................................................................................................................15

5.3 Pressure, Temperature and Gas Composition Influences............................................................................16

6 INDIVIDUAL METER TESTING REQUIREMENTS.....................................................16

6.1 Leakage Tests....................................................................................................................................................17

6.2 Dimensional Measurements.............................................................................................................................17

6.3 Zero-Flow Verification Test (Zero Test)........................................................................................................17

6.4 Flow-Calibration Test.......................................................................................................................................18

6.4.1 Calibration Factors Adjustment .................................................................................................................19

6.4.2 Test Reports.................................................................................................................................................19

6.4.3 Calibration of Metering Package................................................................................................................20

6.4.4 Calibration Adjustment Factors..................................................................................................................20

6.4.5 Test Reports.................................................................................................................................................21

6.4.6 Final Considerations....................................................................................................................................21

6.5 Quality Assurance.............................................................................................................................................22

7 INSTALLATION REQUIREMENTS............................................................................22

7.1 Environmental Considerations........................................................................................................................22

7.1.1 Temperature.................................................................................................................................................22

7.1.2 Vibration......................................................................................................................................................22

7.1.3 Electrical Noise............................................................................................................................................22

7.2 Piping Configuration........................................................................................................................................22

7.2.1 Flow Direction.............................................................................................................................................22

7.2.2 Piping Installations......................................................................................................................................23

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7.2.3 Protrusions...................................................................................................................................................24

7.2.4 Internal Surface...........................................................................................................................................24

7.2.5 Thermowells................................................................................................................................................24

7.2.6 Flow Conditioners.......................................................................................................................................24

7.2.7 Orientation of Meter....................................................................................................................................25

7.2.8 Filtration......................................................................................................................................................25

7.3 Associated Flow Computer..............................................................................................................................25

7.3.1 Flow Computer Calculations.......................................................................................................................25

7.4 Maintenance .....................................................................................................................................................26

8 FIELD VERIFICATION TESTS....................................................................................26

9 ULTYRASONIC METER MEASUREMENT UNCERTAINTY DETERMINATION.......27

9.1 Ultrasonic Meter Calibration Uncertainty....................................................................................................27

9.1.1 Description of a Calibration Process...........................................................................................................279.1.2 Two Components of Uncertainty.................................................................................................................27

9.1.3 Ideal USM Calibration................................................................................................................................27

9.1.4 Realistic USM Calibration..........................................................................................................................28

9.1.5 Uncertainty of Calibration Results..............................................................................................................28

9.1.6 Sample Time Scales.....................................................................................................................................30

9.1.7 Why Group Data?........................................................................................................................................32

9.1.8 Rans Methodology ......................................................................................................................................32

9.2 Ultrasonic meter Uncertainty Determination................................................................................................32

10 REFERENCE LIST....................................................................................................36

APPENDIX A : Multipath Ultrasonic MeterFlow-Calibration Issues ............................ A-1

APPENDIX B : Electronic Design Testing a standardized set of international

testing specifications applicable to electronic gas meters .................... B-1

APPENDIX C : A.G.A. Engineering Technical Note M-96-2-3, Ultrasonic Flow

Measurement for Natural Gas Applications, March 1996 ........................ C-1

APPENDIX D : Flow Meter and/or Flow Conditioner Performance Verification Test .. D-1

FORM FOR PROPOSALS ON A.G.A. REPORT NO. 9......................................................... P-1

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1 Introduction

1.1 Scope

This report was developed for multipath ultrasonic transit-time flow meters, typically 6 and larger in

diameter, used for the measurement of natural gas. Multipath ultrasonic meters have at least twoindependent pairs of measuring transducers (acoustic paths). Typical applications include measuring theflow of large volumes of gas through production facilities, transmission pipelines, storage facilities,distribution systems and large end-use customer meter sets.

1.2 Principle of Measurement

Multipath ultrasonic meters are inferential meters that derive the gas flow rate by measuring the transittimes of high-frequency sound pulses. Transit times are measured for sound pulses transmitted andreceived between pairs of transducers positioned diagonally across the pipe. Pulses transmitted downstream

with the gas flow are accelerated by the flow and pulses transmitted upstream against the gas flow along

the identical acoustic path are decelerated. The difference in these transit times is related to the average gasflow velocity along the acoustic paths. Numerical calculation techniques are then used to compute theaverage axial gas flow velocity and the gas volume flow rate at line conditions through the meter.

The accuracy of an ultrasonic gas meter depends on several factors, such as

Precisely measured dimensions of the meter body and ultrasonic transducer locations

the velocity integration technique inherent in the design of the meter

the quality of the flow profile, levels of pulsation that exist in the flowing gas stream and gasuniformity

the accuracy of the transit-time measurements

The accuracy of the transit-time measurement depends on

the electronic clock stability

accurate, consistent detection of sound pulse transmit and receive times

proper compensation for signal delays of electronic components and transducers

2 Terminology

For the purposes of this report, the following definitions apply:

auditor Representative of the operator or other interested party that audits operation of multipath

ultrasonic meter.

designer Company that designs and constructs metering facilities and purchases multipath ultrasonic

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meters.

inspector Representative of the designer who visits the manufacturers facilities for quality assurancepurposes.

manufacturer Company that designs, manufactures, sells and delivers multipath ultrasonic meters.

operator Company that operates multipath ultrasonic meters and performs normal maintenance.

SPU Signal Processing Unit, the portion of the multipath ultrasonic meter that is made up of theelectronic microprocessor system.

UM Multipath ultrasonic meter for measuring gas flow rates.

3 Operating Conditions

3.1 Gas Quality

The meter shall, as a minimum requirement, operate with any of the normal range natural gascomposition mixtures specified in A.G.A. Report No. 8. This includes relative densities between 0.554(pure methane) and 0.87.

The manufacturer should be consulted if any of the following are expected: 1) acoustic wave attenuatingcarbon dioxide levels are above 10%, 2) operation near the critical density of the natural gas mixture, or 3)total sulfur level exceeds 20 grains per 100 cubic feet (320 PPM approx.), including mercaptans, H 2S and

elemental sulfur compounds.

Deposits due to normal gas pipeline conditions (e.g., condensates or traces of oil mixed with mill-scale, dirtor sand) may affect the meters accuracy by reducing the meters cross-sectional area. Deposits may alsoattenuate or obstruct the ultrasonic sound waves emitted from and received by the ultrasonic transducers,and in some designs reflected by the internal wall of the meter.

3.2 Pressures

Ultrasonic transducers used in UMs require a minimum gas density (a function of pressure) to ensureacoustic coupling of the sound pulses to and from the gas. Therefore, the designer shall specify theexpected minimum operating pressure as well as the maximum operating pressure.

3.3 Temperatures, Gas and Ambient

The UM should operate over a flowing gas temperature range of -13 to 131 F (-25 to 55 C). Thedesigner shall specify the expected operating gas temperature range.

The operating ambient air temperature range should be at a minimum -13 to 131 F (-25 to 55 C). Thisambient temperature range applies to the meter body with and without gas flow, field-mounted electronics,ultrasonic transducers, cabling, etc.

The manufacturer shall state the flowing gas and ambient air temperature specifications for the multipathultrasonic meter, if they differ from the above.

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3.4 Gas Flow Considerations

The flow-rate limits that can be measured by a UM are determined by the actual velocity of the flowinggas. The designer should determine the expected gas flow rates and verify that these values are within the

qmin,qt and qmax specified by the manufacturer (see Section 5.1 for definitions). The accuracy requirementsfor operation within qmin, qt and qmax are stated in Sections 5.2, 5.2.1 and 5.2.2 of this report. The designer is

cautioned to examine carefully the maximum velocity for noise and piping safety (erosion, thermowellvibrations, etc.) concerns.

UMs have the inherent capability of measuring flow in either direction with equal accuracy; i.e., they arebi-directional. The designer should specify if bi-directional measurement is required so that themanufacturer can properly configure the SPU parameters.

3.5 Upstream Piping and Flow Profiles

Upstream piping configurations (i.e., various combinations of upstream fittings, valves, regulators, andlengths of straight pipe) may affect the gas velocity profile entering a UM to such an extent that significant

flow rate measurement error results. The magnitude and sign of the error, if any, will be, in part, afunction of the ability of the meter to correctly compensate for such conditions. Research on the effect ofupstream piping configuration on meter accuracy was still ongoing as of the publication date of this report.In general, research results have shown that this effect is dependent on the meter design, as well as the typeand severity of the flow field distortion produced at the meter. Although a substantial amount of data isavailable on the effect of upstream piping, the full range of field piping installation configurations has notbeen studied in detail. Meter station designers/operators may gain insight into expected meter performancefor given upstream piping installation configurations by soliciting available test results from meter

manufacturers or by reviewing test data found in the open literature. However, to truly confirm meterperformance characteristics for a particular piping installation configuration, flow testing of the meterinstallation is usually required. In order to achieve the desired meter accuracy, it may be necessary for adesigner/operator to alter the original piping configuration or include a flow conditioner as part of the meterinstallation. Further recommendations are provided in Sections 7.2.2 and 7.2.7 of this report.

3.6 Acoustic Noise

Acoustic noise may interfere with ultrasonic pulse detection, and therefore, transit time measurement. Ifthe ultrasonic meter cannot make transit time measurements, gas flow measurements cannot be made.Additionally, acoustic noise interference that causes mis-detection of ultrasonic pulses can result in mis-measurement of transit times and hence volumetric measurement errors. Therefore users must consider

whether interfering acoustic noise is likely to be present in a piping system, and if so, take steps to militateagainst its affects on UM operation to assure reliable and accurate gas flow measurement. It should benoted that acoustic noise which adversely affects meter operation is also ultrasonic, i.e. outside the audiblerange of human hearing. An audibly noisy piping system doesnt necessarily mean there will be problems

with successful UM operation, and conversely, audibly quiet piping systems dont always assure successfulmeter function.

Acoustic noise may be generated in a piping system from numerous sources related to gas flow turbulence:high gas velocities through piping and/or fittings, protruding probes, flow conditioners or pressure andregulating control valves. Interference with ultrasonic pulse detection occurs when the frequency of theacoustic noise is coincident with the meters operating frequency, and is of sufficient amplitude to drownout the ultrasonic pulse. UM manufacturers specify the operating frequencies of their transducers, so thefrequency range in which a particular meter might be affected by acoustic noise is known. Unfortunately

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variable operating conditions (flow, pressure and temperature) and the variety of, and signature frequencies

for, acoustic noise generators, mean that nearly infinite combinations of frequencies and amplitudes mightbe generated which can interfere with ultrasonic pulse detection.

UM manufacturers recognize the potential for operating problems, and most UMs have diagnosticcapabilities that indicate whether acoustic noise impairs meter performance while operating. Strategies

have also been devised by users and manufacturers to estimate and/or limit a UMs susceptibility to noiseinterference:

enhanced signal processing to improve ultrasonic pulse recognition and detection

signal filtering to narrow the bandwidth surveyed for better/faster pulse recognition

installation of fittings, such as blind tees or filters, between the meter and noise source to isolate orreflect noise from the UM

development of specialized silencers that are installed in the piping between UM and noise sourcesto isolate the meter from the offending noise

evaluation of UM response to acoustic noise prior to station installation, based on estimated noisegeneration given operating conditions and piping design, to determine if a given station design willprovide acceptable UM performance

In general, noise sources upstream of UMs have a more adverse impact on meter performance than thoseinstalled downstream (although installing the source downstream of the UM doesnt guarantee it wont

generate interference with the meter). The greater the distance, and number of fittings (tees, elbows, etc),located between a meter and noise source, the greater the noise from the source is attenuated, and theconsequent adverse impact on meter performance reduced.

When considering installation of a UM, particularly in the vicinity of pressure or flow regulation (the mostcommon noise generators), the following factors should be weighed during the station design phase:

the valves (i.e., noise source) installed position relative to the meter; upstream, downstream,distance between meter and source, number and type of fittings between meter and source

operating frequency of the meter, and the range of frequencies generated by the noise source(whisper trim type valves are of particular concern since they achieve operating quietness byusing designs that generate noise in the ultrasonic range: outside of human hearing, but oftentimescoincident with UM operating frequency)

whether, due to the requirement to locate pressure/flow control near a UM, additional attenuationbetween noise source and UM is required

whether enhanced filtering of digital signal processing should be applied, and if so, whether itslows signal processing time beyond acceptable limits (limits prescribed for a linear measuringdevice in API COGFM Chapter 21.1)

the cost/benefit of pursuing one or more strategies to limit UM exposure to offending acousticnoise

If a UM is to be installed near a potential noise source, it is recommended users contact manufacturers forrecommendations specific to their products and the proposed installation prior to finalizing station design.

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Cooperation between users and manufactures during facilities design can avoid the need for potentially

expensive remedial actions at a completed meter installation.

4 Meter Requirements

4.1 Codes and Regulations

The meter body and all other parts, including the pressure-containing structures and external electroniccomponents, shall be designed and constructed of materials suitable for the service conditions for which themeter is rated, and in accordance with any codes and regulations applicable to each specific meter

installation, as specified by the designer.

Unless otherwise specified by the designer, the meter shall be suitable for operation in a facility subject tothe U.S. Department of Transportations (DOT) regulations in 49 C.F.R. Part 192, Transportation ofNatural and Other Gas by Pipeline: Minimum Federal Safety Standards.

4.2 Meter Body

4.2.1 Maximum Operating Pressure

Meters should be manufactured to meet one of the common pipeline flange classes ANSI Class 300,600, 900, etc. The maximum design operating pressure of the meter should be the lowest of the maximumdesign operating pressure of the following: meter body, flanges, transducer connections, transducer

assemblies.

The required maximum operating pressure shall be determined using the applicable codes for the

jurisdiction in which the meter will be operated and for the specified environmental temperature range. Thedesigner should provide the manufacturer with information on all applicable codes for the installation siteand any other requirements specific to the operator.

4.2.2 Corrosion Resistance

All wetted parts of the meter shall be manufactured of materials compatible with natural gas and relatedfluids.

All external parts of the meter should be made of a non-corrosive material or sealed with a corrosion-resistant coating suitable for use in atmospheres typically found in the natural gas industry, and/or as

specified by the designer.

4.2.3 Meter Body Lengths and Bores

The manufacturers should publish their standard overall face-to-face length of the meter body with flanges,for each ANSI flange class and diameter. The designer, as an option, may specify a different length tomatch existing piping requirements.

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The UM bore and the adjacent upstream pipe along with flanges should have the same inside diameter to

within 1% of each other. For bi-directional applications, both ends of the meter should be consideredupstream.

4.2.4 Ultrasonic Transducer Ports

Because natural gas may contain some impurities (e.g., light oils or condensates), transducer ports shouldbe designed in a way that reduces the possibility of liquids or solids accumulating in the transducer ports.

If specified by the designer and available from the manufacturer, the meter should be equipped with valvesand necessary additional devices, mounted on the transducer ports in order to make it possible to replacethe ultrasonic transducers without depressurizing the meter run. In that case, a bleed valve may be requiredin addition to the isolation valve to ensure that no pressure exists behind a transducer before releasing theextraction mechanism.

4.2.5 Pressure Tap

At least one pressure tap shall be provided for measuring the static pressure in the meter for use indetermining corrected volume. Each pressure-tap hole should be between 1/8" and 3/8" nominal in diameterand cylindrical over a length at least 2.5 times the diameter of the tapping, measured from the inner wall ofthe meter body. The tap hole edges at the internal wall of the meter body should be free of burrs and wireedges, and have minimum rounding. For a meter body with a wall thickness less than 5/16", the hole shouldbe 1/8" nominal in diameter.

Female pipe threads should be provided at each pressure tap for a 1/4" NPT or 1/2" NPT isolation valve.Turning radius clearance should be provided to allow a valve body to be screwed directly into the pressure

tap. Pressure taps can be located at the top, left side, and/or right side of the meter body. Additional tapsmay provide the designer with flexibility in locating pressure transducers for maintenance access andproper drainage of gauge line condensates back into the meter body.

4.2.6 Miscellaneous

The meter should be designed in such a way that the body will not roll when resting on a smooth surfacewith a slope of up to 10%. This is to prevent damage to the protruding transducers and SPU when the UMis temporarily set on the ground during installation or maintenance work.

The meter should be designed to permit easy and safe handling of the meter during transportation andinstallation. Hoisting eyes or clearance for lifting straps should be provided.

4.2.7 Meter Body Markings

A nameplate containing the following information should be affixed to the meter body.

the manufacturer, model number, serial number and month and year manufactured

meter size, flange class and total weight

internal diameter

maximum and minimum storage temperatures

body design code and material, and flange design code and material

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maximum operating pressure and temperature range

maximum and minimum actual (at flowing conditions) volumetric flow rate per hour

direction of positive or forward flow

(optional) purchase order number, shop order number and/or user tag number

Each transducer port should be permanently marked with a unique designation for easy reference. If

markings are stamped on the meter body, low-stress stamps that produce a rounded bottom impressionshould be used.

4.3 Ultrasonic Transducers

4.3.1 Specifications

The manufacturers should state the general specifications of their ultrasonic transducers, such as criticaldimensions, maximum allowable operating pressure, operating pressure range, operating temperature rangeand gas composition limitations.

The manufacturer should specify the minimum operating pressure based on the ultrasonic transducermodel, UM size and expected operating conditions. This minimum pressure should be marked or tagged on

the UM to alert the operators field personnel that the meter may not register flow at reduced pipelinepressures.

4.3.2 Rate of Pressure Change

Sudden depressurization of an ultrasonic transducer can cause damage if a trapped volume of gas expandsinside the transducer. If necessary, clear instructions should be provided by the manufacturer fordepressurization and pressurization of the meter and transducers during installation, start-up, maintenance

and operation.

4.3.3 Exchange

It shall be possible to replace or relocate transducers without a significant change in meter performance.

This means that after an exchange of transducers and a possible change of SPU software constants directedby the manufacturer, the resulting shift in the meters performance shall not be outside the limits of theperformance requirements specified in Sections 5.2, 5.2.1 and 5.2.2. The manufacturer should specifyprocedures to be used when transducers have to be exchanged, and possible mechanical, electrical or othermeasurements and adjustments have to be made.

4.3.4 Transducer Tests

Each transducer or pair of transducers should be tested by the manufacturer and the results documented aspart of the UMs quality assurance program. Each transducer should be marked or tagged with apermanent serial number and be provided with the general transducer data listed in Section 4.3.1. If the

SPU requires specific transducer characterization parameters, each transducer or transducer pair shouldalso be provided with test documentation that contains the specific calibration test data, calibration methodused and characterization parameter(s).

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4.4 Electronics

4.4.1 General Requirements

The UMs electronics system, including power supplies, microcomputer, signal processing components andultrasonic transducer excitation circuits, may be housed in one or more enclosures mounted on or next tothe meter and is referred to as a Signal Processing Unit (SPU).

Optionally, a remote unit containing the power supplies and the operator interface could be installed in anonhazardous area and connected to the SPU by multi-conductor cable.

The SPU should operate over its entire specified environmental conditions within the meter performancerequirements specified in Sections 5.2, 5.2.1 and 5.2.2. It should also be possible to replace the entire SPUor change any field replacement module without a significant change in meter performance. Significantchange is explained in Section 4.3.3.

The system should contain a watch-dog-timer function to ensure automatic restart of the SPU in the eventof a program fault or lock-up.

The meter should operate from a power supply of nominal 120V AC or 240V AC at 50 or 60 Hz or from

nominal 12V DC or 24V DC power supply/battery systems, as specified by the designer.

4.4.2 Output Signal Specifications

The SPU should be equipped with at least one of the following outputs.

serial data interface; e.g., RS-232, RS-485 or equivalent

frequency, representing flow rate at line conditions

The meter may also be equipped with an analog (4-20mA, DC) output for flow rate at line conditions.

Flow-rate signal should be scaleable up to 120% of the meters maximum flow rate, qmax.

A low-flow cutoff function should be provided that sets the flow-rate output to zero when the indicatedflow rate is below a minimum value (not applicable to serial data output).

Two separate flow-rate outputs and a directional state output or serial data values should be provided forbi-directional applications to facilitate the separate accumulation of volumes by the associated flowcomputer(s) and directional state output signal.

All outputs should be isolated from ground and have the necessary voltage protection to meet theelectronics design testing requirements of Appendix B.

4.4.3 Electrical Safety Design Requirements

The design of the UM, including the SPU, should be analyzed, tested and certified by an applicablelaboratory, and then each meter should be labeled as approved for operation in a National Electric CodeClass I, Division 2, Group D, Hazardous Area, at a minimum. Intrinsically safe designs and explosion-proof enclosure designs are generally certified and labeled for Division 1 locations. The designer mayspecify the more severe Division 1 location requirement to achieve a more conservative installation design.

Cable jackets, rubber, plastic and other exposed parts should be resistant to ultraviolet light, flames, oil andgrease.

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4.4.4 Component Replacement

The ability to replace or relocate transducers, cables, electronic parts and software without a significant orappreciable change in the meters performance is a requirement. The manufacturer shall provide provenprocedures for the user and sufficient data to demonstrate that following the replacement or relocationprocedure for any of these components will not shift the meter outside the performance requirements in

section 5.2, 5.2.1 or 5.2.2.

Changing any of these components without recalibration may lead to additional uncertainties, the level ofwhich must be specified by the manufacturer.

Additionally, for replacement of a component that affects a single path (i.e. transducer, cable), the velocityof sound measured on the altered path shall be within the smaller of

1. 0.05% of the mean of the velocities of sound measured by the undisturbed paths or

2. 25% of the average difference between the speed of sound of the unaltered paths as compared tothe altered path at the meters last field test.

4.5 Computer Programs

4.5.1 Firmware

Computer codes responsible for the control and operation of the meter should be stored in a nonvolatilememory. All flow-calculation constants and the operator-entered parameters should also be stored innonvolatile memory.

For auditing purposes, it should be possible to verify all flow-calculation constants and parameters whilethe meter is in operation.

The manufacturer should maintain a record of all firmware revisions, including revision serial number, dateof revision, applicable meter models, circuit board revisions and a description of changes to the firmware.

The firmware revision number, revision date, serial number and/or checksum should be available to theauditor by visual inspection of the firmware chip, display or digital communications port.

The manufacturer may offer firmware upgrades from time to time to improve the performance of the meteror add additional features. The manufacturer shall notify the operator if the firmware revision will affect

the accuracy of a flow-calibrated meter.

4.5.2 Configuration and Maintenance Software

The meter should be supplied with a capability for local or remote configuring of the SPU and for

monitoring the operation of the meter. As a minimum, the software should be able to display and record thefollowing measurements: flow rate at line conditions, mean velocity, average speed of sound, speed ofsound along each acoustic path and ultrasonic acoustic signal quality received by each transducer. As anoption, the manufacturer can provide these software functions as part of the meters embedded software.

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4.5.3 Inspection and Auditing Functions

It should be possible for the auditor or the inspector to view and print the flow-measurement configurationparameters used by the SPU; e.g., calibration constants, meter dimensions, time averaging period and

sampling rate.

Provisions should be made to prevent an accidental or undetectable alteration of those parameters thataffects the performance of the meter. Suitable provisions include a sealable switch or jumper, a permanentprogrammable read-only memory chip or a password in the SPU.

(Optional) It should be possible for the auditor to verify that all algorithms, constants and configurationparameters being used, in any specific meter, are producing the same or better performance as when themeter design was originally flow-tested or when the specific meter was last flow-calibrated and anycalibration factors were changed. The auditor may have to rely on the manufacturer for portions of thisverification because of the proprietary nature of some UM algorithms.

In general, the metering system should conform to the requirements provided in American PetroleumInstitutes Manual of Petroleum Measurement Standards Chapter 21.1 for electronic gas measurement. Inaddition, the operator should baseline the meter by documenting the relationship between path transit time(if available), path automatic gain control (AGC), path velocity of sounds, meter average velocity of sound,meter average velocity (were applicable), and meter uncorrected volume (were applicable) during meter dry

calibration, flow calibration , and initial installation. These baseline relationships are useful in establishingacceptance criterion and determining the need for meter recalibration after changing components and/orfirmware

4.5.4 Alarms

The following alarm-status outputs should be provided in the form of fail-safe, dry, relay contacts or

voltage-free solid-state switches isolated from ground.

output invalid: when the indicated flow rate at line conditions is invalid

(optional) trouble: when any of several monitored parameters fall outside of normal operation for asignificant period of time

(optional) partial failure: when one or more of the multiple ultrasonic path results is not usable

4.5.5 Diagnostic Measurements

The manufacturer should provide the following and other diagnostic measurements via a serial datainterface; e.g., RS-232, RS-485 or equivalent.

average axial flow velocity through the meter

flow velocity for each acoustic path (or equivalent for evaluation of the flowing velocity profile)

speed of sound along each acoustic path

average speed of sound

velocity sampling interval

averaging time interval

percentage of accepted pulses for each acoustic path

status and measurement quality indicators

alarm and failure indicators

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4.5.6 Engineering Units

The following units should be used for the various values associated with the UM.

Parameter U.S. Units SI Units

density lb/cf kg/m3

energy Btu J

mass lb kg

pipe diameter in mm

pressure psi or lbf/in2 bar or Pa

temperature F C

velocity ft/s m/s

viscosity, absolute dynamic lb/(ftsec) cP or Pasvolume cf m3

actual (at flowing conditions) volume flow rate acf/h am3/h

4.6 Documentation

Other sections of this report require documentation on accuracy, installation effects, electronics, ultrasonic

transducers and zero-flow verification. The manufacturer should also provide all necessary data,certificates and documentation for a correct configuration, set-up and use of the particular meter so that itoperates correctly. This includes an operators manual, pressure test certificates, material certificates,measurement report on all geometrical parameters of the spool piece and certificates specifying the zero-flow verification parameters used. Quality-assurance documentation should be available for the inspectoror the designer upon request.

The manufacturer should provide the following set of documents, at a minimum. All documentation shouldbe dated.

a. a description of the meter, giving the technical characteristics and the principle of its operation

b. a perspective drawing or photograph of the meter

c. a nomenclature of parts with a description of constituent materials of such parts

d. an assembly drawing with identification of the component parts listed in the nomenclature

e. a dimensioned drawing

f. a drawing showing the location of verification marks and seals

g. a dimensioned drawing of metrologically important components

h. a drawing of the data plate or face plate and of the arrangements for inscriptions

i. a drawing of any auxiliary devices

j. instructions for installation, operation, periodic maintenance and trouble-shooting

k. maintenance documentation, including third-party drawings for any field-repairable components

l. a description of the electronic SPU and its arrangement, and a general description of its operation

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m. a description of the available output signals and any adjustment mechanisms

n. a list of electronic interfaces and user wiring termination points with their essential characteristics

o. a description of software functions and SPU configuration parameters, including their default valueand operating instructions

p. documentation that the design and construction comply with applicable safety codes and

regulationsq. documentation that the meters performance meets the requirements of Section 5, Performance

Requirements

r. documentation that the meters design successfully passed the tests in Appendix B, ElectronicsDesign Testing

s. upstream and downstream piping configurations in minimum length that will not create an

additional flow-rate measurement error of more than 0.3%

t. maximum allowable flow-profile disturbance, which will not create an additional flow-ratemeasurement error of more than 0.3%

u. a field verification test procedure as described in Section 8

v. a list of the documents submitted

4.6.1 After Receipt of Order

The manufacturer should furnish specific meter outline drawings, including overall flange face-to-facedimensions, inside diameter, maintenance space clearances, conduit connection points and estimatedweight.

The manufacturer should provide a recommended list of spare parts.

The manufacturer should also furnish meter-specific electrical drawings that show customer wiringtermination points and associated electrical schematics for all circuit components back to the first isolatingcomponent; e.g., optical isolator, relay, operational amplifier, etc. This will allow the designer to properlydesign the interfacing electronic circuits.

4.6.2 Before Shipment

Prior to shipment of the meter, the manufacturer should make the following available for the inspectorsreview: metallurgy reports, weld inspection reports, pressure test reports and final dimensionalmeasurements as required in Section 6.2.

5 Performance Requirements

This section specifies a set of minimum measurement performance requirements that UMs must meet. If ameter is not flow-calibrated, the manufacturer shall provide sufficient test data confirming that each metershall meet these performance requirements. It is recommended that UMs be flow calibrated per Section 6.4to improve measurement accuracy beyond the minimum performance requirements. When a meter is flow-calibrated it shall meet the minimum measurement performance requirements detailed below before theapplication of any calibration-factor adjustment. The amount of calibration-factor adjustment, therefore,

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should be within the error limits stated in these performance requirements. This is to ensure that a major

flaw in the meter is not masked by a large calibration-factor adjustment.

Calibration-factor adjustments are made to minimize a meters measurement bias error. The designer isreferred to Appendix A and Section 6.4.1 for an explanation of the methods and benefits of flow-calibratinga meter and for calibration-factor adjustment. The designer should also follow carefully the installation

recommendations of Section 7, as any installation effects will add to the overall measurement uncertainty.

For each meter design and size, the manufacturer shall specify flow-rate limits for q min, qt and qmax as

defined in Section 5.1. Each UM, whether flow-calibrated or not, shall perform within the more accuratemeasurement range for gas flow rates from qt to qmax and within the less accurate range for gas flow ratesless than qt but greater than or equal to qmin, as defined in Sections 5.2, 5.2.1 and 5.2.2.

5.1 Definitions

Percent error ((Measured value reference value) / reference value) x100.

Error The result of a measurement minus the true value of themeasurand.

Note 1: Since a true value cannot be determined, in practice a

conventional true (or reference) value is used.

Mean error The arithmetic mean of all the observed errors or data pointsfor a given flow rate.

Maximum Error The allowable error limit within the specified operationalrange of the meter, as shown in Figure 1 and Sections 5.2.1and 5.2.2.

Maximum Peak-to-Peak Error The largest allowable difference between the upper-most

error point and the lower-most error point as shown inFigure 1 and Section 5.2. This applies to all error values inthe flow-rate range between qt and qmax.

Maximum Error Shift with

One Path Failed

The maximum deviation between the error observed, at oneflow rate, with all paths in operation compared to the error,at the same flow rate, with any one of the meters paths

inactive.

Speed of Sound Accuracy: The maximum error, in percent, between the metersreported speed of sound, determined at the time of drycalibration, and that calculated for nitrogen.

Maximum SOS Path Spread The maximum difference between any paths permittedduring the dry calibration on nitrogen.

qmax The manufacturer stated maximum gas flow rate throughthe meter (see Figure 1).

qt The flowrate at which the allowable error changes. (SeeFigure 1).

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qmin The minimum gas flowrate through the meter as specifiedby the manufacturer (See Figure 1).

qi The actual measured gas flowrate passing through a meterunder a specific set of test conditions.

Reference Meter A meter or measurement device of proven flowmeasurement accuracy.

Repeatability (when discrete error values are given) The closeness ofagreement between successive flow rate measurements whenobtained under the same conditions (same fluid, same flowmeter, same operator, same test facility, and a short intervalof time, and without disconnecting or dismounting the flowmeter).

Repeatability (when discrete error values are not given) The acceptable errortolerance within which 95% of all flow rate errors must lie,when obtained under the same conditions (same fluid, same

flow meter, same operator, same test facility, and a shortinterval of time, and without disconnecting or dismountingthe flow meter).

Reproducibility The closeness of agreement among a number of consecutivemeasurements of the output of the test meter for the same

reference flow rate under the same operating conditionsfrom one day to the next.

Resolution The smallest step change of flow velocity that is indicatedby the meter. See Section 5.2.

Velocity Sampling Interval The time interval between two succeeding gas velocity

measurements by the full set of transducers or acousticpaths. Typically, between 0.05 and 0.5 seconds, dependingon meter size. See Section 5.2.

Zero-Flow Reading The maximum allowable flow-velocity reading when the gasis at rest. That is both the axial and non-axial velocity

components are essentially zero. See Section 5.2.

Note : Mean error to be determined for at least six different flow rates, such as 2.5, 5, 10, 25, 50, 75, 100percent of maximum flow rate. A 95% confidence level of the mean error shall be reported for the datacollected at each flowrate along with the number of samples used to compute the interval. A minimum

number of three flow rate error values shall be determined at each flow rate.

Calibration Verification Test Points:

The meter user is left to specify the number of flow rate verification points after the application of a singlemeter calibration factor.

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5.2 General

The general flow-measurement performance of all UMs shall meet the following requirements, prior tomaking any calibration-factor adjustment.

Repeatability: 0.2% for qt qi qmax

0.4% for qmin qi < qt

Resolution: 0.003 ft/s (0.001 m/s)

Velocity Sampling Interval: 1 second

Maximum Peak-to-Peak Error:

(See Figure 1)

0.7% for qt qi qmax

0.4% for qt qi qmax after flow calibration

Zero-Flow Reading:


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Flow rate (qi)

-1.6

-1.4

-1.2-1.0

-0.8

-0.6

-0.4

-0.2

-0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

Percenterror

qmin qmaxqt

Repeatability 0.2% (qi qt)

Large meter error limit +0.7%

Large meter error limit -0.7%

Small meter error limit +1.0%

Small meter error limit -1.0%

Expanded error limit +1.4% (qi


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6.1 Leakage Tests

Every UM, complete with transducers and transducer isolation valves (if used), shall be leak-tested by themanufacturer after final assembly and prior to shipment to the designer or flow-calibration facility. The test

medium should be an inert gas, such as nitrogen. The leak test pressure shall be a minimum of 200 psig,maintained for a minimum of 15 minutes, with no leaks detectable with a noncorrosive liquid solution or an

ultrasonic leak detector as described in ASTM E 1002 - 93. This leak test does not preclude therequirements to perform a hydrostatic qualification test.

6.2 Dimensional Measurements

The manufacturer shall measure and document the average internal diameter of the meter, the length ofeach acoustic path between transducer faces and the axial (meter body axis) distance between transducerpairs.

The average internal diameter should be calculated from a total of 12 inside diameter measurements or theequivalent determined by a coordinate measuring machine. Four internal diameter measurements (one in the

vertical plane, another in the horizontal plane and two in planes approximately 45 from the vertical plane)shall be made at three meter cross-sections: 1) near the set of upstream ultrasonic transducers, 2) near theset of downstream transducers and 3) half way between the two transducer sets.

If the acoustic path lengths or the axial distances between ultrasonic transducer pairs cannot be directlymeasured, then the unknown distances shall be calculated using right-angle trigonometry and distances thatcan be measured directly. Where the measurement of angles is difficult and the result is imprecise, suchmeasurements shall not be used to calculate the required distances.

The meter body temperature shall be measured at the time these dimensional measurements are made. Themeasured lengths shall be corrected to an equivalent length at a meter body temperature of 68 F (20 C)by applying the applicable coefficient of thermal expansion for the meter body material. The individual

corrected lengths shall then be averaged and reported to the nearest 0.0001" (0.01 mm).

All instruments used to perform these measurements shall have valid calibrations traceable to nationalstandards; e.g., NIST in U.S.A.

These measurements and calculations shall be documented on a certificate, along with the name of themeter manufacturer, meter model, meter serial number, meter body temperature at the time dimensionalmeasurements were made, date, name of the individual who made the measurements and name of theinspector if present.

6.3 Zero-Flow Verification Test (Zero Test)

To verify the transit-time measurement system of each meter, the manufacturer shall perform a Zero-FlowVerification Test. The manufacturer shall document and follow a detailed test procedure that includes the

following elements, at a minimum.

After blind flanges are attached to the ends of the meter body, the meter shall be purged of all airand pressurized with a pure test gas or gas mixture. The selection of the test gas shall be theresponsibility of the manufacturer. However, the acoustic properties of the test gas must be well-known and documented.

The gas pressure and temperature shall be allowed to stabilize at the outset of the test. The gasvelocities for each acoustic path shall be recorded for at least 30 seconds. The mean gas velocityand standard deviation for each acoustic path shall then be calculated.

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Adjustments to the meter shall be made as necessary to bring the meter performance into

compliance with the manufacturers specifications and the specifications stated in this report.

If the measured speed-of-sound values are compared with theoretical values, the theoretically determinedvalue shall be computed using a complete compositional analysis of the test gas, precise measurements ofthe test gas pressure and temperature and the equation of state used in AGA Report No. 10, Speed ofSound in Natural Gas and Other Related Hydrocarbon Gases or another method that produces results that

agree with those derived using AGA Report No. 10 to within 50 parts per million.

As part of the test procedure, the manufacturer shall document the ultrasonic transducer serial numbers andtheir relative locations in the meter body. The manufacturer shall also document all parameters used by themeter; e.g., transducer/electronic transit-time delays, incremental timing corrections, and all acoustic path

lengths, angles, diameters and other parameters used in the calculation of the gas velocity for each acousticpath. The manufacturer should note if the constants are dependent on specific transducer pairs.

The manufacturer may also implement a zero-flow offset factor, in engineering units of positive or negativefeet per second or meters per second. This zero-flow offset factor would be applied to the meters flow-rateoutput. Use of this factor is intended to improve the accuracy of the low gas velocity measurements, whilenot significantly affecting the accuracy of the higher velocity measurements. This zero-flow offset factor, if

used, shall be documented by the manufacturer.

6.4 Flow-Calibration Test

It is a requirement that all custody transfer metering packages be flow calibrated in a flow calibrationfacility traceable to a recognized national/international standard. Examples of national standards are NIST,

NMI and PTB standards. The following nominal flow rates are recommended at minimum: qmin, 0.10qmax, 0.25 qmax, 0.40 qmax, 0.70 qmax, and qmax. The designer may also specify additional flowcalibration tests at other flow rates. (See the example in appendix A, where additional tests at 0.15 qmaxand 0.20 qmax could be useful).

It is also a requirement that the specific piping configurations and/or flow conditioners be used during flow

calibration, understanding that differences in upstream piping configurations may influence the metersoutput. It is desirable to calibrate the entire metering system as a package in the calibration facility (i.e.customer supplied piping and flow conditioner along with meter).

Designers should provide the calibration facility with the following information:

1. Meter size.

2. Piping data (i.e. schedule, id, lengths and ANSI rating).

3. Flow conditioner(s) type and placement.

4. Maximum flow rate or velocity (Should be manufactures stated qmax).

5. Output signal to be used for calibration. (Serial data, frequency or analog)

6. Position of thermo well(s) and/or temperature element (Appendix C, Sec.3.2.2).

7. Additional data points if desired.

8. A drawing clearly showing the installation should be provided.

9. Any special instructions should be noted (e.g. for bi-directional calibrations either rotate meter

only or rotate meter and meter tubes).

Most calibration facilities provide the customer with a pre-calibration checklist (See example).

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Any property or thermo physical value (e.g. density, compressibility, speed of sound, critical flow factor,

etc) used during flow calibration shall be computed using methods from A.G.A. Report No. 8, DetailedCharacterization Method Equation of State. The speed of sound shall be computed using the method inAGA Report No. 10, Speed of Sound in Natural Gas and Other Related Hydrocarbon Gasses or anothermethod that produces results that agree with those derived using AGA Report No. 10 to within 50 parts permillion.

If the manufacturer recommends any changes to the meter configuration prior to calibration then thelaboratory will be responsible for making these changes according to the manufacturers recommendedmethod.

The laboratory shall maintain a record of the initial meter configuration as received from manufacturer andkeep a record of all subsequent changes.

Throughout this section, the section will reference USM diagnostics that are variable. Since the parametersare variable, users are recommended to calculate a rolling average for each of the parameters. Unlessspecified otherwise, when the section refers to the meter diagnostics, it is actually referring to the rollingaverage of the diagnostic parameters. The size of the rolling average will depend on the variability of thedata; however, typically a rolling average of at least 100 samples would be appropriate.

6.4.1 Calibration Factors Adjustment

Meter packages will consist of adequate upstream and downstream piping and/or flow conditioning toensure that there is not significant difference between gas profile as seen by the meter in the laboratory andthe gas profile as seen in the final installation.

Each manufacturer is responsible for providing statistics developed from path velocity data, which will beused to determine acceptable variations in profile during calibration and variations from laboratory to finalinstallation. The ability to transfer the accuracy of the laboratory meters to the custody transfer meteringpackage is limited by the ability to reproduce the profile as seen by the meter in the lab, in the field

installation.

(Appendix X or Section 8.) will provide the direction for profile analysis and other meter diagnostics usedto evaluate meter performance.

All thermo wells and/or sample probes should be installed for the calibration. All flanges should be alignedto minimize any protrusions. Position of primary temperature sensing element should be reviewed. Section7.2 provides guidance for piping configurations.

6.4.2 Test Reports

It is recommended that the calibration facility inspect the meter for any obvious physical damage that mayhave occurred during shipping and verify that the physical meter configuration matches the configurationspecified by the user.

It is also recommended that the calibration laboratory verify the electronic configuration in the metermatches the configuration provided by the manufacturer with the supplied meter.

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To identify meter problems it is recommended to perform a zero flow verification test prior to calibrating

the metering package. This should be done as per the manufacturers specification and should includeverification of the individual gas velocities, speed of sound and per path performance.

Unless specified otherwise by the manufacturer, the meter log must then be evaluated as follows.

It is recommended that no individual path velocity be greater than .04ft/sec on average. The speed of sound

per path should be within .2% of the theoretical value (See Appendix C Section 3.1). The performance perpath should be 100%. All gain levels should be within the nominal limits provided by the manufacturer.Once all of the above conditions are satisfied, the calibration may commence.

Finally, the laboratory shall configure the test in such a way that the meter is calibrated using the outputsignal requested by the end user.

6.4.3 Calibration of Metering Package

The calibration will involve flowing gas though one or more reference meters in series with the meter under

test at the flow rates outlined above. Flow, temperature, pressure and gas composition data will be acquiredand an error for the meter will be calculated at each flow rate.

All calibrations will be designed using sound statistical techniques to determine the number of calibrationpoints, the number of samples at each point and the size of each sample.

A calibration point will be derived from a statistically significant measurement. A calibration point willconsist of at least 300sec or 400D/v of data (flow dynamic considerations paper).

At least one verification point will be taken after applying adjustment factor as outlined below. This willinvolve the repeat of one test point taken during calibration to verify the adjustment was calculated andapplied properly.

During the calibration, meter log data will be accumulated at each flow rate. At least 100 samples at each

flow rate are required. This data can be used to develop a finger print of the meters performance(Appendix X). At least one SOS check should be done during the calibration.

6.4.4 Calibration Adjustment Factors

Calibration adjustment factors should normally be applied to eliminate any indicated meter bias error. Thetwo accepted methods of applying adjustment factors are:

1) Using the flow-weighted mean error (FWME) over the meters expected flow range(Calculation of FWME is shown in Appendix A).

2) Using a more precise error correction scheme (e.g. polynomial algorithm, a piecewise linearinterpolation method, etc)

For bi-directional flow calibrations, a second set of calibration adjustment factors can be used for reverseflow where possible. If only one calibration adjustment factor is available, the adjustment should reflectaverage adjustments of both the forward and reverse calibrations. The resulting, as left calibration resultsmust meet the accuracy specification as outlined in this document.

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6.4.5 Test Reports

The results of each test required in Section 6 shall be documented in a written report supplied to thedesigner or the operator. For each meter, the report shall include at a minimum:

1) The name of the manufacturer

2) The name and address of the facility

3) The model and serial number of the meter

4) The SPU firmware revision number

5) The date(s) of the test

6) The name and title of the person(s) who conducted the tests

7) A description of test procedures

8) The upstream and downstream piping configuration including flow conditioner

9) The serial numbers of all piping and flow conditioners.

10) A diagnostic report of the software configuration parameters

11) All test data, including flow rates, velocities, errors, pressure, temperature and gascomposition

12) A statement of uncertainty for the facility

13) An indication of adjustment applied and adjustment factors used

At least one copy of the complete report shall be sent to the designer or the operator. For new meters onecopy will be retained in the manufacturers files. The manufacture shall ensure that the complete report isavailable to the operator upon request, for a period of 10 years after shipment of any meter.

6.4.6 Final Considerations

Upon completion of the calibration, the complete metering package will be marked to indicate alignment offlanges at time of calibration. The end users can request that the flanges directly up and downstream of themeter be dowelled to ensure exact positioning upon reassembly in the field. Designers may consider leaving

the complete metering package assembled for shipment to final installation location. Flow conditioneralignment should also be marked if not already done so by the flow conditioner manufacturer. In mostcases, thermo wells may remain installed to ensure proper installation in the field.

Write protect jumpers/switches should be installed and sealed to prevent metrology affecting parameterchanges. A copy of the final meter parameter file should accompany the meter to the field installation

location.

Meter log analysis and SOS checks should be included to provide a fingerprint of the metering packageperformance. This fingerprint can be used to verify the field installation of the package upon startup. It isalso useful for the historical health checks of the metering package. It is recommended that themanufacturers provide the parameters that define the fingerprint for their products.

Unless specified otherwise by the manufacture, the laboratory diagnostic data will be verified and the

fingerprint factors

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To identify meter problems it is recommended to perform a zero flow verification test prior to calibrating

the metering package. This should be done as per the manufacturers specification and should includeverification of the individual gas velocities, speed of sound and per path performance.

Unless specified otherwise by the manufacturer, the meter log must then be evaluated as follows.

6.5 Quality Assurance

The manufacturer shall establish and follow a written comprehensive quality-assurance program for theassembly and testing of the meter and its electronic system (e.g., ISO 9000, API Specification Q1, etc.).This quality-assurance program should be available to the inspector.

7 Installation Requirements

This section is directed to Designer to ensure that the UM will be installed in a suitable environment and ina piping configuration in which the UM can meet the expected performance requirements.

7.1 Environmental Considerations

7.1.1 Temperature

The Manufacturer shall provide ambient temperature specifications for the UM. Consideration should begiven to providing shelter, heating, and/or cooling to reduce the ambient temperature extremes.

7.1.2 Vibration

UMs should not be installed where vibration levels or frequencies might excite the natural frequencies ofSPU boards, components, or ultrasonic transducers when installed in the meter body. The Manufacturershall provide specifications regarding the natural frequencies of the UM components.

7.1.3 Electrical Noise

The Designer and the Operator should not expose the UM or its connected wiring to any unnecessaryelectrical noise, including alternating current, solenoid transients, or radio transmissions. TheManufacturer shall provide instrument specifications regarding electrical noise influences.

7.2 Piping Configuration

7.2.1 Flow Direction

For bi-directional applications, both ends of the meter should be considered "upstream."

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7.2.2 Piping Installations

As previously noted in Section 3.5, various combinations of upstream fittings, valves, and lengths of

straight pipe can produce velocity profile distortions at the meter inlet that may result in flow ratemeasurement errors. The amount of meter error will be dependent on the type and severity of the flowdistortion produced by the upstream piping configuration and the meters ability to compensate for this

distortion. Research work on installation effects is ongoing, so the Designer should consult with theManufacturer to review the latest test results and evaluate how a specific UM design may be affected bythe upstream piping configuration of the planned installation. In order to achieve the desired meterperformance, it may be necessary for the Designer to alter the original piping configuration or include aflow conditioner as part of the meter run.

To ensure that the UM, when installed in the operators piping system, will perform within the specified

flow rate measurement accuracy limits defined in Sections 5.2, 5.2.1 and 5.2.2, the manufacturer shall doone of the following, as directed by the designer/operator:

1. Recommend at least one upstream and downstream piping configuration, without a flow conditionerand one configuration with a flow conditioner, that will not create an additional flow rate measurementerror of more than +0.3% due to the installation configuration. This error limit should apply for any

gas flow rate between qmin and qmax. This recommendation should be supported by test data.

2. Specify the maximum allowable flow disturbance (e.g., the limits on swirl angle, velocity profileasymmetry, turbulence intensity, etc.) at the meters upstream flange, or at some specified axialdistance upstream of the meter, that will not create an additional flow rate measurement error of morethan +0.3% due to the installation configuration. This error limit should apply for any gas flow rate

between qmin and qmax. This recommendation should be supported by test data.

Instead of following the manufacturers recommendation in 1 or 2 above, the Designer may choose to flowcalibrate the UM in-situ, or in a flow calibration facility in which the test piping configuration is identicalto the planned installation. By the law of similarity, it is presumed that the field installed meter willperform the same way as it did in the flow calibration facility.

Research has demonstrated that asymmetric velocity profiles may persist for 50 pipe diameters or moredownstream from the point of initiation. Swirling velocity profiles may persist for 200 pipe diameters ormore. A flow conditioner properly installed upstream of a UM may help shorten the length of straight piperequired to eliminate the effects of an upstream flow disturbance. A UM may be able to compensate forsome level of flow profile disturbance. Research is still being conducted to quantify the sensitivity ofdifferent UM designs to various flow profile disturbances.

When any of the previously discussed conditions exist in the field installation, that are different from the

aga-9 revision draft 082403

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